Fluids, such as oil, natural gas and water, are obtained from a subterranean geologic formation or porous reservoir by drilling a well that penetrates the fluid-bearing reservoir. This provides a flowpath for the fluid to reach the surface. In order for fluid to be produced from the reservoir to the wellbore there must be a sufficient flowpath from the reservoir to the wellbore. This flowpath is through formation rock of the reservoir, such as sandstone or carbonates, which has pores of sufficient size and number to allow a conduit for the fluid to move through the porous reservoir formation.
In the past, in addition to a principal wellbore extending through the formation, wellbores have been utilized with lateral sections. One technique, referred to as a Maximum Reservoir Contact (MRC) well, comprises a principal wellbore with a plurality of lateral sections extending from it. The principal advantage of a MRC well is its ability to reach a larger area of the reservoir and thus to produce at a substantially higher rate. However, sand from the formation tends to flow into the primary wellbore from the lateral wellbore sections. Combating the problem of sand production associated with the lateral wellbore sections is expensive and difficult, and often is not completely successful.